Thursday, March 22, 2018

Exploration Technology in an Era of Change

"We've got to be careful how we define economic. Advances in technology make what is uneconomic today economic tommorow. Take deep water development. Five years ago we would have said a water depth of 4000 ft [1220 m] in the Gulf of Mexico is a no-no. Now, no problem. So when we talk about economic elephants, we are often talking about waiting for development technology to catch up to make those elephant economic. And the technology is catching up rapidly."

 "I'd like to offer a dissenting opinion and address the onshore prospects that a smaller company can deal with. I believe that if there are large fields left in the US, they are probably low-resistivity pay and stratigraphic traps that are virtually invisible to conventional technology. A lot of bright people have looked for oil and gas in the US, using mostly 1975-vintage technology. Very few explorationist have been equipped with a scanning electron microscope,modern seismic surveys, and expert petrography and log analysis. Very few know how to apply hydrodynamics or surface geochemistry. This is one of the great opportunities still left for "value-added production" - perhaps not on the scale of finds in Indonesia or Africa, but important nonetheless." 

" We think of multidisciplinary integration as a core competency - we are only as good as our ability to develop options based on our multidisciplinary evaluation of data. Accessing technology, with a capital "T", we do mainly by looking to the outside world. 
We think about exploration Technology in broad terms. We line up our technology under three banners : (1) techniques that reduce finding and development costs, (2) those that shorten the time between discovery and production, and (3) those that improve fluid recovery. For us, 3D seismic plays a role in all three categories and increasingly is routinely integrated with other data. "

" I think the major change for us was the power of integrating geochemical with geological, reservoir geophysical and other kinds of data on the workstation and the linkage of many workstations and data bases. The interpreter or interpreting team has access to a variety of information and modeling software, including balancing geologic sections, basin modeling. This approach requires more teamwork and further integration of staff specialist in the exploration and development process."

"There is another technical challenge that I alluded to earlier: finding all those now-invisible stratigraphic traps. Sequence stratigraphy is a key to some problems. For gas wells, an understanding of overpressure is essential. "

"We bypassed several reservoirs in Nigeria and the US Gulf Coast because they were not recognized on the logs. We discovered them by doing reservoir geochemistry on cores. The methods don't work so well on cuttings, so we are trying to collect more sidewall cores in problematic areas. The geochemistry itself is cheap- about $150 per sample."


Wednesday, March 21, 2018

Paleomagnetics for Logging

Nobody knows exactly why the earth's magnetic field switches polarity, but the fact that it does and for variable a new logging method enabling well-to-well correlations and the potential for absolute age determination in basin core. When rocks are formed, those that are magnetically susceptible record the direction and magnitude of the this remanent magnetism, the primary objective of paleomagnetic research , has now been applied to the borehole.

The earth's magnetic field is believed to be generated by some form of self-exciting dyanamo. This happens within the earth's iron-rich liquid outer core as it spins on its axis. Fluid motion in the liquid part of the core and activity in central solid part, give rise to local perturbations of the earth's field and also lead to variations in pole positions lasting from 1 year to 10^5 years. Even more intriguing is that complete reversals of the magnetic field occur-north pole becomes south pole and vice versa. These geomagnetic polarity reversals take about 5000 years to complete and last from 10^4 to 10^8 years. Nobody knows the cause, but the reversal process does not involve the magnetic pole simply wandering from north to south. The magnetic field strength appears to fade close to zero and then gradually increases in the opposite direction until a complete reversal is achieved.

How do we know all this? Records of Earth's magnetic field strength and direction date back only a few hundred years and do not show reversals. The first proof of a geomagnetic reversal was provided in 1906 by a French physicist, Bernard Brunhes, when he discovered volcanic rocks at Pontfarein in the French Massif Central that were magnitized almost exactly in the opposite direction to the present-day geomagnetic field. This led to the belief that rocks could retain magnetization from previous magnetic fields, a phenomenon called natural remanent magnetism (NRM).

If no remagnetization occurs - remagnetization is a possibility if rocks are reheated, exposed to later magnetic fields or chemically altered- NRM is an imprint of the geomagnetic field existing at the freezing time of lavas or at the deposition time of sedimentary rocks. And, unlike most geological events, the direction of the NRM imprint is the same worldwide. Traditional dating techniques, such as isotopic or biologic methods, and accurate NRM measurements allow comparison of geochronological time scales with polarity reversals. 

Because of the random time distribution of polarity reversals, a sequence of four or five is unique, almost like a bar code.  A borehole reading of this magnetic reversal sequence (MRS) promises a direct correlation with GPTS. Because MRS is measured against depth and GPTS against time, correlation between them infers a sedimentation rate. 

During the formation of a basin, sedimentation rate varies, but the variation is not random and it is strictly independent of changes in magnetic polarity. This means that sedimentation rate must not exceed a limit compatible with the lithology and must not change drastically at each reversal. Hence, the rate can not only be determined, but can also be used to check the quality of match between one MRS and another or between MRS and the GPTS.

Correlations that indicate a fluctuating sedimentation rate may either be incorrect or may indicate unconformities where part of the geological record in the MRS is missing.

Magnetic reversal sequences can also be used to provide well-to-well correlation. In a hypothetical example representing a series of coastal onlap sequences, the main limits of sedimentary bodies have been determined. Accurate time correlations are now possible and cleary show zones where sedimentation is continous and those where unconformities. Combining both sets of data provides a complete sedimentary description of the basin. The relationship between sedimentary bodies is shown to be more complex than originally assumed.

Basics of Paleomagnetism
Natural remanent magnetism is mostly carried by ferromagnetic minerals, such as iron oxides (hematite, magnetite, goethetie) and iron sulfides (pyrrhotite, but not pyrite), that have high magnetic susceptibility, meaning they are easily magnetized in the presence of a magnetic field. Unlike paramagnetic minerals such as clays, which have small positive susceptibility, or diamagnetic minerals such as limestone or sandstone, which have slightly negative susceptibility, ferromagnetic minerals retain some magnetism after the magnetic field is removed.


Wednesday, March 14, 2018

Measurements at the Bit: MWD Tools

Measurements-while-drilling technology has moved down the drillstring to enlist the bit itself as a sensor. 

Conventional drilling of high-angle and horizontal wells is like piloting an airplane from the tail rather than the cockpit. Information required to land the well in the target formation is derived from sensors 50 ft or more behind the bit or at the surface. Because these measurements -about well trajectory, drilling efficiency and formation properties -are remote from the bit, crucial drilling decisions are delayed and data may require more complex interpretation. In particular, course corrections are delayed by lag in measurements needed to make steering decisions, resulting in less drainhole in the pay zone. Also, maximum drilling efficiency requires information about mechanical power delivered to the bit, which is inferred from surface measurements, degrading its accuracy. And resistivity measurements from logging-while-drilling (LWD) sensors in drill collars are limited to formation resistivity less than 200 ohm-m.

Despite these limitations, horizontal and high-angle drilling have proved successful, especially in simple geologic settings - uncomplicated layer-cake structure. Nearly, all these  wells start vertically, with a conventional rotary bottomhole assembly (BHA). The drillstring and bit are rotated from the surface either by a rotary table on the derrick floor or a motor in the traveling block, called a topdrive. Drilling this way is called rotary mode. To kick-off from vertical, the rotary assembly is replaced with a steerable motor - usually a positive displacement motor, driven by mud flow, in a housing bent 1 degree to 3 degree. When mud is flowing , the motor rotates the bit, but not the drillstring. This type of drilling is called sliding mode, because the drillstring slides along after the bit, which advances in the direction of the housing below the bend. 

The direction in which the bit is pointing, called toolface, is measured and sent to surface by measurement-while-drilling (MWD) equipment for real-time control of bit orientation. Measurements include azimuth, which is the compass bearing of the bit, and inclination, which is the angle of the bit with respect to vertical. Large changes in direction are made by lifting off bottom and reorienting the bent sub by rotating from surface. Small changes are made by varying weight on bit, which changes the reactive torque of the motor and hece toolface orientation.

Once sufficient inclination has been built, straight or tangent sections can be drilled in several ways. One is with a conventional rotary, or "locked" , assembly, which is rigid enough to allow fast, straight drilling. Small adjustments in inclination can be made by varying weight on bit or rotary speed. Most horizontal sections, and some tangent sections, are drilled with a steerable motor while rotating the drillstring from surface. In this mode, the steerable motor behaves like a rotary BHA, maintaining both azimuth and inclination. 

However, the presence of the steerable motor allows the driller to make course corrections without tripping the drillstring out of the hole. 

Generally, the driller tries to make as much hole as possible using a rotary assembly or a steerable motor in rotary mode. Rotation of the drillstring reduces the risk of getting stuck and allows faster drilling than in sliding mode.

Overcoming limitations in horizontal drilling

Today, the ability to drill horizontally is undisputed. Yet, the efficiency of drilling and steering horizontally is limited by the distance between the bit and measurements. In drilling, for example, one way to define efficiency is the ratio of time spent making hole to the total rig time, including operations such as trips or hole conditioning. In the horizontal section, steering efficiency can be defined as the ratio of the length of the horizontal section in the pay zone to the total length of the horizontal section. How does lag between measurements and the bit limit these efficiencies?

In drilling with a downhole motor in rotary mode, a key limitation on efficiency is how much weight the driller can safely apply to steerable motor. As the driller increases weight , the motor produces more torque, and power is torque times RPM. The more power, the faster the rate of penetration -up to a point. Excess weight may stall and eventually damage the motor, requiring an expensive trip for motor replacement. The goal is to apply as much power as possible, but within the operational limit of the motor. Power is estimated conventionally from surface measurements of mud flow and mud pressure. Motor RPM is roughly proportional to mud flow. Torque is roughly proportional to the increase in the mud pressure when the bit is on the bottom, compared to off bottom. 

Perhaps the greatest limitation in conventional horizontal drilling is in steering efficiency. Wells are conventionally steered "geometrically" - along a path that has been predetermined based on nearby well data and geologic assumptions. Steering is based only on bit direction and inclination data. Gamma ray and resistivity measurements, if present, are made far from the bit and used only retrospectively. This technique is fine, as long as the target is thick, structurally simple and well known. But it is less effective when the target is thin, complex or insufficently known for planning the well trajectory. And increasingly, with advances in three-dimensional seismics, operators are locating more intricate reservoirs and drilling more complex wells. Challenges today include thin beds and complexly folded or faulted reservoirs.

In these settings, sensors in drill collars allow replacement of basic geometric steering with more efficient geologic steering, or "geosteering" - navigation of the bit using real-time information about rock and fluid properties. A North Sea example shows how LWD sensors performed the dual purpose of geosteering and formation evaluation. Using mostly resistivity measurements, the driller geosteered a drainhole along the top of the oil/water contact to avoid gas production. Resistivity modeling from offset wells showed this contact should have a resistivity of about 0.6 ohm-m. When the value dropped, indicating water , the well path was turned up slightly; when resisitivity increased, the well path was dropped slightly.  

In addition to reduced efficiency in drilling and geosteering, a third limitation of conventional horizontal drilling is in formation evaluation while drilling. Logging-while-drilling sensors reach the formation long before wireline measurements, and so generally view it before wellbore degradation, but some invasion has still occured. Rapid invasion, called spurt, may mask true resistivity in some formations. Also, LWD resistivity measurements by the CDR Compensated Dual Resistivity tool are limited to environments favoring induction-type settings -resistive mud (fresh or oil-base mud) and conductive rock.

The solution to these problems -limited efficiency in drilling and geosteering, and limited capabilities of real-time formation evaluation - is relocation of drilling and logging measurement to the bit itself. The system includes two new logging devices : the Geosteering tool , an instrumented steerable downhole mtoor and the RAB Resisitivy-At-the-bit tool, an instrumented stabilizer. Measurements include gamma ray, several types of resistivity including a measurement at the bit, and drilling data such as inclination, bit shocks and motor RPM. 

The technical leap that allows measurements to be made at the bit and below the steerable motor is a wireless telemetry system. This telemetry link sends data from sensors near the bit to the MWD tool up to 200 ft behind the bit, a path that bypasses the intervening drilling tools, such as the steerable motor. The PowerPulse MWD system recodes and then sends data to surface in real time using mud-pulse telemetry at up to 10 bits per second. At surface, data recording, interpretation and tool control are performed by the Wellsite Information System. Control data can be sent from the surface back downhole by varying mud pump flow. 

The geosteering tool enables the driller and geologist to make real-time correction at the bit, detect hydrocarbons at the bit and steer the borehole for increased reservoir exposure. Both tools measure gamma ray, resistivity using the bit as electrode, and "azimuthal" resisitivy - focused at a narrow angle along the borehole wall. 

Resistivity at the bit is measured by attaching the Geosteering or RAB tool directly to the bit and driving an alternating electric current down the collar, out through the bit and into the formation. The current returns to the drillpipe and drill collars above the transmitter. In water-base mud, returning current is conducted from the bit through the mud, into the formation and back to the BHA. In oil-based mud, which is an insulator, current returns through the inevitable but intermittent contact of the collars and stabilizers with the borehole wall, leading to a qualitative indication of resistivity. Formation resisitivy is obtained by measuring the amount of current flowing into the formation from the bit, and normalizing it to the transmitter voltage. 

Azimuthal resistivity is measured from one or more button electrodes and , like the azimuthal gamma ray measurement, can be used to steer the bit. Both tools can be oriented in multiple directions to find the location of a lithologic or pore fluid boundary relative to the borehole -up, down, left or right - and thereby steer the bit. 

Surface Control for Measurements at the Bit

Because the Geosteering tool is an instrumented steerable motor, it enables the driller to steer the bit on a geometric or geologic path through the pay zone.  The driller's window into the bit is the Wellsite Information System, which includes a display for checking and revising the structural and stratigraphic model, and updating the drilling trajectory. This screen is intended mainly for real-time management of horizontal drilling. 

 Resolution of both Geosteering tool and RAB Resistivity measurements is sufficient for hydrocarbon detection and lithologic correlation. The multiple depths of investigation and high resolution of the focused RAB measurements also provide formation evaluation-quality information. Applications include prompt location of coring and casing points, and monitoring of invasion by logging after drilling.

Thursday, March 1, 2018

Drilling and Testing High Pressure High Temperature Wells

High-temperature, high pressure (HTHP) wells present special challenges to drill and test. Predominantly gas producers, HTHP wells may yield significant reservers in some areas. But the wells stretch conventional equipment beyond normal operational capacities. To safely meet these extreme conditions, traditional procedures have been modified and extra operational controls devised. 

 What constitutes HTHP is debatable. Perhaps the best definition has been coined by the UK departemen of energy:
"wells where the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 300 F (150 degree celcius) and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic gradient of 0.8 psi/ft or pressure control equipment with a rated working pressure in excess of 10,000 psi is required.

HTHP drilling is not new. In the late 1970s and early 1980s, many gas wells were drilled in the Tuscaloosa trend, Lousiana, USA, and other southern US states. These encountered temperatures above 350 degree F (177 C) and presures of more than 16,000 psi, not to mention highly corrosive environments. When HTHP interest switched to the North Sea in the mid 80s, new hazards were introduced. The wells were drilled offhsore, in exteremely hostile conditions and sometimes using floating semisubmersible rigs rather than fixed jackups.

Most of the North Sea HTHP wells are situated in the Central Graben - a series of downthron and upthrown blocks.  

The Central Graben contains several Jurassic gas condensate prospects at 12,000 to 20,000 ft [3660 to 6100 m] , with pressures of 18,000 psi or more and temperatures of up to 400 F [205 C].

 Water depth in the Central Graben varies between 250 to 350 ft [75 to 105 m] . Both jackups and semisubmersibles have successfully drilled wells in the sector, harsh environment jackups up to about 300 ft and semisubmersibles for deeper water. Jackups offer the advantage of contact with the seabed, eliminating heave and simplifying many drilling and testing operations. On the downside , in an emergency , jackups cannot be moved off location quickly. Also, few deepwater jackups are available.

This article looks at three key areas of HTHP operations in the UK Central Graben: drilling safety, casing and cementing, and testing. It also examines how North Sea experience has been used to help convert a jackup to drill demanding wells off Brunei. 

Drilling Safety

Preventing and controlling influxes of reservoir fluid into the well -called kicks- are always central to drilling safety, but in HTHP wells the dangers from a kick are amplified. The volume of a HTHP gas kick remains virtually unchanged as it rises in the annulus from 14,000 to 10,000 ft [4265 to 3050 m]. From 10,000 to 2000 ft [610 m] its volume triples. But from 2000 ft to the surface, there is a hundred-fold expansion.

Put simply, a gas influx of 10 barrels at 14,000 psi becomes 4000 barrels under atmospheric conditions. As reservoir fluid rapidly expands, it forces mud out of the well -unloading - reducing mud in the well, cutting hydrostatic pressure at the formation, allowing additional reservoir fluids to enter, and ultimately causing a blowout.

Wells drilled in the Central Graben have another complication - an unpredictable and sharp increase in pore pressure over a short vertical interval, sometimes less than 100 ft [30m]. And, while the pore pressure may rise rapidly, the fracture pressure does not. In some cases, convergence of pore and fracture pressures means that a small decrease in the mud weight of 0.5 pounds per gallon [lbm/gal] or less changes the well from losing circulation to taking a kick.

The difficulty of drilling in the Central Graben was highlighted in September 1988 when a blowout on the semisubmersible Ocean Odyssey resulted in fire and loss of life. Consequently, the UK Department of Energy esentially banned the drilling and testing of prospects with anticipated reservoir pressures exceeding 10,000 psi.

Because the consequences of failure in HTHP wells are so great, worst-case scenarios tend to be more conservative than for normal wells. Usually, the maximum anticipated size of a kick is set at the limit of detection -often 10 to 20 barrels. In HTHP wells, many contigency plans are based on the worst case of an influx completely filling the well at reservoir pressure.

When drilling with oil-base mud (OBM), there is a likelihood that gas entering the wellbore will dissolve into the mud's oil phase. This affects how the kick moves up the annulus and may mask detection. Since 1986, researchers at Schlumberger  have been studying the behavior of gas kicks, particularly in OBM. 

Planning requires realistic data: well temperature profile, nature of the anticipated reservoir fluids, expected maximum bottomhole pressure and pressure gradient, and rock strength and permeability. These are most often estimated using offset data -relatively plentiful in the North Sea. But where offset data are sketchy, predictive modeling may be employed. Shell has developed a model to predict rock strength and pore pressure in many areas of the North Sea. Shell has also modified a model designed to predict wellhead temperatures in offshore production wells to estimate surface equipment temperture when controlling a kick. 

Worst-case scenarios are used not only to specify equipment but also to draw up specific operational procedures, for example detailing what to do if the well takes a kick. Training is then used to comunicate these procedures to drilling personnel. Long before drilling starts, specific HTHP training courses may be run. Once on the rig, there are prespud meetings, crew safety meetings before starting key sections of the well, preshift meetings to discuss the current situation, and regular drills to practice important techniques like closing blowout preventers (BOP).

The three issues at the heart of HTHP drilling safety are kick prevention, kick detection and well control.

The best way of avoiding well-control problems is to anticipate situations known to precipitate kicks and take preventive action. Here are four examples:
  • When high-pressure formations are drilled, kicks commonly occur when the drilling assembly is being pulled out of hole. The movement of the assembly creates a piston effect reducing pressure below the bit, called swabbing. A time-consuming routine is usually adopted to check whether swabbing will cause an influx.
  • Before the assembly is pulled out of hole, the mud at the bit is circulated to surface - a procedure called circulating bottoms up. If this is free from gas, ten stands of drillpipe are pulled. The string is then run back to total depth (TD), and bottoms up are circulated. Gas in the mud is measured again, with an increase indicating swabbing. If swabbing does cause an influx, the mud weight may be raised slightly and the string pulled out of hole more slowly. Also, circulating mud while pulling out of hole helps stop swabbing -a process made easier by topdrive. 
  • The combination of relatively high-viscosity mud, deep wells and small annular clearences leads to higher than normal friction pressure during mud circulation. At the formation, mud hydrostatic pressure and friction pressure then combine to give the equivalent circulating density (ECD). This may be designed to balance formation fluid pressure. But during a connection, mud flow stops and friction pressure is zero. Witch reduced ECD, small quantities of gas, called connection gas, may permeate from the formation. 
  • Kicks don't occur just during drilling coring also causes problems. The relatively small clearence between core barrel and open hole increases the possiblilty of swabbing when pulling out of hole. This may be combated by limiting the amount of core cut any one time - usually to 30 ft or less - and pulling out of hole very slowly, checking for flow and monitoring gas in the mud.
  • Tight margins between pore pressure and rock strength ,as in the Central Graben, make lost circulation common, complicating well control. The normal practice on encountering losses is to pump lost circulation material (LCM) in the mud. If LCM fails to block the formation, the strategy is to pull out of hole, run back in with open-ended pipe and spot cement across the loss zone. Some slurry is squeezed into the formation and, once set, the remainder drilled out. However, in HTHP wells, the swabbing effect of pulling the bottomhole assembly out of hole prior to spotting the plug may induce a kick elsewhere in the wellbore. In this case, the only solution is to spot the cement plug through the bit. To make this easier, rotary drilling is favored, rather than using a downhole motor that may clog up with cement.

 Kick Detection: Because no technique can guarantee kick-free drilling, influx detection remains vitally important. Traditional influx detection relies on observing mud level increases in the mud pits, or performing flow checks - stopping drilling to see if the well is flowing. Comparisons of mud flow rates into and out of the well are also used. To make detection more reliable, transfer of mud into the active system is tightly controlled and usually not allowed while drilling.

Recently, Anadrill has introduced the KickAlert early gas detection service based on the principle that acoustic pulses created by the normal action of the mud pumps travel more slowly through mud containing gas they do through pure mud. The pulses are measured as pressure variations at the standpipe as the mud enters the well and at the annulus as it comes out. If the well is stable and no gas is entering, the phase relationship between the pressure pulses in the standpipe and annulus is constant, or changes gradually as the well is drilled deeper. When gas enters, the pulses travel much more rapidly up the annulus, dramatically changing the phase and setting off an alarm on the drillfloor. 

 The presence of high-pressure gas may also be indicated by changes in drilling conditions. Increases in rate of penetration, torque or mud temperature in the mud return flowline on surface may all signify the onset of a kick. Computerized monitors help drilling personnel keep track of trends and spot abnormal situations using quick-look interpretations on a drillfloor screen.

Well Control: As soon as a kick is detected, drilling is stopped and the well is shut in. The influx must then be circulated out while keeping the presssure under control. 
The BOPs are the primary means of well closure. Once a kick is suspected, the annular blowout preventer is first closed. A flexible rubber element is inflated using hydraulic pressure, and is sufficiently flexible to seal around any downhole equipment. When it has been established that no tool joints are in the way, the pipe rams are then shut, sealing around the drillpipe. Now mud can no longer return through the flowline to the shale shakers and mud pits. Instead it must travel through the chokeline to the choke manifold, which is used to relieve mud pressure at surface.

The capacity of a BOP to resist pressure depends on the elastometric seals inside the rams and their likelihood of not being extruded. As temperature increases, extrusion becomes more likely. Seals may have to withstand prolonged temperatures that top 400 degree F - beyond the limit of ordinary components. Finite-element analysis has been used to identify which areas of the BOPs are most affected by heat and which seals need special elastomers rated to 350 degree F. 

Once the BOPs and choke are closed, pressure builds in the annulus and drillpipe. The maximum drillpipe pressure is used to calculate bottomhole pressure, which is used to plan the kill strategy. Well-kill strategy also takes into consideration the drilling operation underway during the kick.

If the kick occurs during drilling, weighted mud - either from a premixed or specially prepared supply - may immediately be pumped down the drillpipe. The formation fluid influx is gradually displaced up the annulus, expanding as hydrostatic pressure decreases. At surface, the mud-influx mixture travels to the choke manifold via the chokeline and has its pressure reduced by the choke. The well is slowly brought under control by carefully selecting mud weight and choke opening.

Casing and cementing 

In Central Grabben wells, choosing the location of the intermediate -usually 9 5/8 in. -casing shoe is crucial. Ideally, casing must be set above the high pressure reservoir and just below a zone of weak Hod chalk.

If it is set too high, the weak formation will be exposed to subsequent high pressure, and the only solution is to set a short, perhaps less than 100 ft, 7-in. drilling liner. This has the undesirable effect of reducing the diameter of further drilling.

Consequently, the  shoe is usually set at the bottom of the Hod chalk, in the Lower Cretaceous clays or in the Kimmeridge clay just above the reservoir. But finding the casing point is not easy - vertical seismic profile surveys may be employed. As drilling approaches the likely casing point, it is intermittenly halted, bottoms up circulated and cuttings examined by a geologist or micropaleogeologist.

Pressure is a key consideration when designing the casing string. The 9 5/8-in casing is often designed to withstand complete evacuation to atmospheric presssure with reservoir pressure in the annulus between open hole and casing. Given the high pressures, heavy-weight casing is usually required throughout the string.

Once the casing string has been run, the shoe must be cemented to resist the high reservoir pressure that will be encountered almost as soon as the next section of drilling starts. Location of the top of cement (TOC) of the 9 5/8 in. casing is sometimes an issue. I normal wells the TOC is usually above the previous casing shoe, with fluid trapped in the annulus above the TOC. When the HTHP wells are drilled, hot mud passing up the drillpipe-casing annulus heats fluid in the casing-casing annulus, causing it to expand.
For a subsea-HTHP well, the presure has no escape and it can burst or collapse the casing. For this reason, the TOC for 9 5/8 in. casing in a HTHP well is sometimes kept below the 13 3/8 in. shoe to allow annular pressure to dissipate into the formation.

In most HTHP wells a 7-in. liner is run, although in some cases it may be possible to cement a 7-in. casing to surface. In either case, the cement job must isolate the high-pressure zones to facilitate well testing. This requires good cementing practices and a carefully designed slurry.

Mud removal is vital in achieving strong cement bonding to the formation and casing, and sealing against high pressure. Even small quantities of contaminant in the cement slurry compromise the final setting strength. Spacers reduce contamination, but high temperatures may thin or destroy spacer polymers causing weighting agents to settle.

The tight pressure constraints found in HTHP wells mean that the traditional density hierarchy -  cement heavier than the mud with an intermediate spacer -is difficult to achieve without exceeding formation fracture pressure. A viscosity hierarchy is also desirable, but when cement is thicker than mud , the friction pressure may increase beyond the limit. This emphasizes the importance of other good drilling and cementing practices: drilling an even wellbore, circulating and conditioning the mud correctly, and centralizing the casing.

In gas zones with a low overbalance, there is the risk that high-pressure gas will enter the cement during hydration and create large channels. Elsewhere, loss of fluid into the formation reduces the slurry liquid-to-solid ratio, changing rheology, density and setting time.

Once the 7-in. liner is cemented, casing pressure tests simulate losing control during well testing and exposing the entire string to formation pressure. Test are generally carried out using a retrievable packer set above the theoretical top of cement in the annulus. 

Testing :

Cores are taken and logs run where possible and used to decide whether and where to test. Coring may be limited by its prospensity to swab the well and cause kicks. For logging, the tolerance of all standard wireline logging tools to high temperature may be boosted by thermal insulation.

Once  cores and logs have indicated the presence of hydrocarbons, a well test is needed to determine parameters like reservoir extent and permeability, and to sample reservoir fluid. In almost all cases, a cased-hole drillstem test is used. The well is normally shut in using a downhole valve and flow is controlled at surface using a choke manifold. Periods of flow and shut-in allow collection of data like flow rate and pressure changes. 

The rates and pressures experienced during testing HTHP wells are prodigious. One test by Ranger Oil Ltd. in the Centrl Graben using a jackup rig resulted in 44 MMscf/D of gas and 4400 B/D of condensate. The maximum recorded tubing-head pressure was 12,500 psi, the bottomhole temperature was 386 degree F (197 degree C.

Downhole Equipment:

Sealing off the candidate formation requires a packer. During an HTHP test, differential pressures across the packer may exceed 10,000 psi. For this reason, permanent packers are usually chosen, rather than  retrievable packers used in lower pressure test. With wireline (or very ocassionally drillipipe), the packer is installed complete with a sealbore, and a seal assembly is then run with the test string to seal into the packer.

Perforating with wireline guns is generally avoided during HTHP tests, so tubing-conveyed perforating (TCP) is preferred. Unlike wireline perforating, TCP allows the reservoir to be perforated underbalanced and immediately flowed through the test string.Because the guns will spend hours in the well prior to firing, high-temperature explosive is used. In most cases, the TCP guns are run as part of the test string, rather than hung off below the packer. This reduces the time that the explosives spend downhole and allows the guns to be retrieved in case of total failure. 

In most cases, test tools are operated using annular pressure. The condition of the fluid in the annulus, usually drilling mud, plays a critical factor. High-density, high-solids drilling fluid may plug pressure ports and reduce tool reliability. Solids may also settle, potentially sticking the test string. The effects on heavy, water-base mud of being static in a hot well have been thoroughly investigated in the laboratory and the performance of test tools has been improved to reduce downhole failures. In some cases, the annular fluid is changed to high-density brine, which is solids free but increases the expense of the test.

Friday, February 23, 2018

Borehole Stability

Rock mechanics theory and practice are being stretched to their limit to solve severe borehole stability problems in the tectonically active Cusiana field of Colombia. The earth scientists' and drilling engineers' main challenge is estimating those most elusive of all earth parameters, subsurface stress and rock strength. What they find out can influence the entire development strategy of this newly discovered, giant field.

 Drilling and maintaining in-gauge hole remains one of the driller's greatest challenges. In-gauge, stable hole not only means trouble-free drilling, it also helps ensure that logs are of high quality, that the cement job runs smoother, and that every subsequent action in the well occurs to the operator's maximum advantage. Everything in the oilfield starts with the drillhole, so ensuring the hole possible is worth some thought and expense.

Fighting for hole integrity, the driller must monitor and juggle two key factors- mud chemistry and mud weight. Mud and formation must be balanced chemically, particulary in shales, to prevent the formation swelling against the drillpipe or sloughing into borehole. Simultaneously, a mechanical balance must be achieved to prevent two well-known phenomena - breakouts and formation fracturing -and ,as experts now suspect, maybe also a third phenomenon called shear displacement.  This article focueses on how the mechanical balance is monitored and achieved, and reviews the latest theories and measurement techniques in a case study from the newly discovered Cusiana field in eastern Colombia.

Rock in its natural state is stressed in three principal directions - vertically from the overburden, Sv, horizontally in two orthogonal directions. The two horizontal stresses are generally not equal - the maximum and minimum horizontal stresses are expressed as SH and Sh, respectively.

As a borehole is driled, hydraulic pressure of the drilling mud must replace the support lost by removal of the original column of rock. But mude pressure being uniform in all directions cannot exactly balance the earth stress. Consequently, rock surrounding the borehole is distorted or strained, and may fail if the redistributed stresses exceed rock strength.

One failure mechanism is tensile failure. This occurs when hydraulic pressure of the mud becomes too high, causing formation stress at the borehole wall to go into tension  and exceed the rock's tensile strength. This fractures the rock along a plane perpendicular to the direction of the earth's minimum stress, generally one of the horizontal stresses, and potentially causes lost circulation.

Alternatievely, the formation can fail in compression. This is commonly predicted using the Mohr-Coulomb model, in which the factors controlling failure are the minimum and maximum stresses at the borehole wall- the intermediate stress is assumed to have no effect. Compressive failure may be caused by too low or too high a mud weight. In either case, formation caves in or spalls off, creating breakouts. The debris can then accumulate in the borehole leading to stuck pipe or even hole collapse.

The third, recently discovered mechanism of mechanical instability is shear displacement. In this, mud pressure is high enough to reopen naturally existing fractures that intersect the borehole. As the fracture is opened, stresses along it are temporarily relieved, and opposite faces of the fracture can physically shear, creating a small but potentially dangerous dislocation in the borehole. The phenomenon was first identified by Elf geologist Maury and Sauzy in agas field in the southeast France.

 The bottom line for the driller striving to maintain a stable hole is choosing the right mud weight. First, mud weight must be sufficient to exceed formation pore pressure, not a mechanical stability issue but essential for preventing kicks. Second, it must be high enough to avoid the low mud-weight mode of compressional failure. Third, it must not be too high that the formation fails in tension or in the high mud-weight mode of compressional failure. Fourth, it must not be too high to initiate shear displacement.

Steering a middle course would be challenging enough in a thick, homogeneous bed, but in reality drillers must maintain stability over long openhole sections with varying lithology, strengths and stresses. And generally speaking, the middle course is harder to find the more the well is deviated. When the going gets too rough, casing gets set. But while drilling continues, all available measurements and knowledge, particualry experience drilling nearby wells, must be applied to choose optimum mud weight.

The key parameters for evaluating stability are simply the three principal components of earth stress and rock strength parameters defining tensile and compressional failure. Once these are known, computer programs seedily calculate the principal stresses at the borehole wall, and predictions of failure can be obtained. But both earth stresses and rock failure are extraordinarily difficult to assess accurately, and a successful resolution must use an integration of all available methods of obtaining them. Most of these methods have been brought to bear with some success in the Cusiana field where drillers have faced immense drilling problems.

The Cusiana field lies in the eastern foothills of the Andes. Discovered in 1991 by BP exploration company (Colombia) Ltd. with partners Total Compagnie Francaise des Petroles and Triton Energy Corp., the field promises to be in the top 50 oil reserves of the world. Drilling the discovery wells, though, proved a driller's nightmare with mechanical stability problems causing stuck pipe, damaged casing and sidetracks. BP estimates that approximately 10% of well cost is spent coping with bad hole. Average rig time to reach oil-bearing sediments at more than 14,000 ft [4200 m] has been 10 months. 

Although both chemical and mechanical factors inevitably contribute to bad hole in the Cusiana field, the operators had no doubt that mechanical stability was the prime cause. The field lies on the eastern flank of the Oriental Andes cordillera, an area being actively compressed by the eastward thrust of the Pacific "Nazca" plate and the more southeasterly thrust of the Carribean plate. 

Three fault blocks are being compressed in the Cusiana region with faults striking parallel to the cordillera - the Yopal block under the cordillera, the Cusiana block containing the reservoir, and the Llanos block under the plains to the southeast. The reservoir is situated in the Cusiana block between the Yopal and Cusiana thrust faults.

Generally, in quiescent geological areas, vertical stress caused by the weight of the overburden is greater than either of the two horizontal stresses. Geologists suspected this might be the case in the Yopal block, where there seemed to be enough minor faulting to relieve the large horizontal stress induced by tectonic deformation. But in the Cusiana block and particularly the Llanos block, it was thought that horizontal stress in the northwest-southeast direction was still high, almost certainly greater than the vertical stress. 

 Drillers became convinced of this as severe drilling problems developed in the Carbonera formations in the middle of the Tertiary zone. The Carbonera formation is an interbedded sequence of sands, mudstones and shales comprising eight units. As a result, a task force comprising BP, Total, Triton and Schlumberger experts was convened to measure and understand the Cusiana stress field and attempt to resolve the drilling problems.

The techniques that are being used to evaluate the Cusiana stress field are multifarious. Some remain to be implemented, others already have been. They include: 
  • computer simulation of the region's tectonic deformation.
  • Analysis of the breakouts on caliper logs to determine the direction of minimum horizontal stress.
  • Analysis of oriented cores to evaluate stress direction and possibly magnitude.
  • Use of extended leakoff test to evaluate horizontal stress magnitudes and calibrate an earth stress model.

BP's computer simulation of tectonic deformation in the three blocks confirmed that in most of the region, horizontal stress in the direction of tectonic compression -that is, in a northwest-southeast direction, normal to the cordillera -was the maximum stress. With no compression, vertical stress was greater than the normal horizontal stress. But with some compression, normal horizontal stress increased, eventually becoming larger than the vertical stress. 

In the field, the direction of least horizontal stress can be confirmed by observing breakouts using caliper logs. Breakouts, caused by the borehole being in compressional failure, have been observed worldwide to cause ovalization of the borehole with oval's long axis parallel to the minimum stress. In several Cusiana wells, breakouts have been evaluated using the dual caliper and borehole drift measurements of dipmeter and resistivity imaging tools. The caliper pairs, oriented at 90 degree , provide information about borehole enlargement. The tools' navigation system measures orientation and deviation of the borehole and establishes tool azimuth.

Breakouts can be picked automatically from logs using the Breakout Orientation Log (BOL) program. This reviews the caliper pairs and flags zones where one pair is close to bit size while the other is significantly larger. Furthermore, their difference has to materialize quickly versus depth to distinguish potential breakouts from irregular washout. Once flagged, the long axis of the breakout can be oriented with the borehole drift and tool azimuth measurements. The results in the Cusiana field have a striking consistency, showing breakout and therefore direction of minimum horizontal stress oriented between 30 degree and 60 degree that is, southwest-northeast.

A more common and certainly more reliable method of measuring earth stress is through extended leakoff, or minifrac tests. Normal leakoff tests are systematically performed by drillers to investigate rock strength after casing is set. The hole is drilled out several feet below casing and borehole fluid pressure is increased by pumping small quantities of additional mud into the well. At first, the pressure builds up linearly. But when formation at the borehole wall cracks and mud begins to leak off, presssure increases less fast. The point where this change occurs gives the leakoff pressure. In the Cusiana field, BP has so far performed 35 leakoff test in 11 wells.

The extended leakoff test is a riskier exercise for the driller and one not contemplated during the trials of drilling the current Cusiana wells. As before, mud is pumped until intial failure of the formation at the borehole wall. But then more mud is pumped to create full fracture - this occurs at the slighty higher breakdown pressure, Pbd. As the fracture forms, pressure usually drops. After the fracture is extended for a while, pumping is stopped, and pressure is carefully monitored as the fracture closes. At the very moment of closure, the pressure levels of slightly. Pressure at the point exactly equals the minimum horizontal stress, Sh. In a second cycle, mud can be pumped again to reopen the fracture. The difference between Pbd and the pressure required to reopen gives the tensile strength of the formation, T0.

Basic borehole stability theory shows that in the case of initiating a vertical fracture, leakoff pressure, Plo , is

Plo= 3Sh-Sh + To- Pp'

where Pp is formation pore pressure, measurable using RFT Repeat Formation Tester or MDT Modular Formation Dynamics Tester tools. 


At 8500 ft [2590 m] in one of the Cusiana wells, a leakoff pressure of 14.4 lbm/gal was recorded -effective mud weight is used here instead of absolute pressure. Pore pressure was known to be equivalent to 8.96 lbm/gal and the formation was assessed as being very weak so T0 was ignored. The above equation then gives that Sh equals 19.84 lbm/gal. Integrating the density log in the well provided a vertical stress of 20.2 lbm/gal, so it appears in this case that Sh = Sv> Sh.

Stress estimates from leakoff data are obtained at sporadic depths only, so the next step is interpolating them to obtain a continous estimate versus depth. This is achieved in two steps. First, the stress estimates are used to calibrate a simple earth model that relates horizontal stresses to the vertical stress. Second, with log data as input, the model is used to evaluate the horizontal stresses foot by foot down to reservoir depth.

Several models are available. One assumes the earth behaves elastically, squeezed vertically by the overburden and laterally by tectonic forces ; another assumes that as overburden increases, the earth continually fails according to the Mohr-Coulomb criterion. In all these models, horizontal and vertical stresses are related via the formation's elastic constants, and these are derivable only from wireline logs of density and compressional and shear acoustic velocity.

Density and compressional acoustic velocity have long been standard wireline measurements, but only recently has a shear velocity logging measurement been feasible in all types of formation - previously it could be measured in hard formation, but not in soft formation such as shales, mudstones and sands.

Conventional sonic logging tools employ a monopole energy source that produces an omnidirectional pressure pulse in the mud that excites both compressional and shear waves in the formation. But the shear waves are detectable in the borehole only if their velocity is faster than the acoustic velocity of the mud, not the case when logging soft formations. In the new DSI Dipole Shear Sonic Imager tool, a dipole source displaces the borehole horizontally to create both shear and flexural waves in the formation. Together, these provide a measurable shear velocity in any formation type.

After earth stress versus depth is evaluated, the next step toward assessing safe mud weight is estimating rock strength, in both compression and tension. This can be achieved in the laboratory with destructive testing of core samples, or, in the absence of cores, using correlations from logging measurements. Several correlations are used. In one, compressive strenth is made a function of porosity, in another it is a function of the rock's shear modulus. In all cases, the same three logging measurements - density, compressional acoustic velocity and shear acoustic velocity are usually required. 

 A borehole stability log over 4000 ft [1200 m] of troublesome formations in one of the Cusiana wells is shown with highly compressed vertical scale. The caliper log in track 1 shows severe washouts in the top half of the section and slightly better hole condition in the lower half. Track 2 shows three elastic parameters calculated from density and acoustic measurements. The high Poisson ratio of 0.30 and relatively low Young modulus of 3x10^6 psi indicate that all formations are fairly weak.